UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

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FORM 10-Q

|(Mark One)                                                      |                                                                                         
|--------------------------------------------------------------- | ----------------------------------------------------------------------------------------
|ý                                                               | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 
|For the quarterly period ended September 30, 2007              
|or                                                             
|o                                                               | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
|For the Transition Period
from                               to

Commission File Number: 0-06910

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TEL OFFSHORE TRUST(Exact name of registrant as specified in its charter)

|Texas(State or other jurisdiction
of incorporation or organization)                                                         |  | 76-6004064(I.R.S. Employer Identification No.)
|--------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------------
|The Bank of New York Trust
Company, N.A., Trustee
919 Congress Avenue
Austin, Texas(Address of principal executive offices) |  | 78701(Zip Code)                               
|(800) 852-1422(Registrant's telephone number, including area code)                                                         

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.    Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.

(Check
one): Large Accelerated Filer o        Accelerated
Filer o        Non-accelerated filer ý

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act).    Yes o No ý

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. As of November 14,
20074,751,510 Units of Beneficial Interest in TEL Offshore Trust.



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NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included in this Form 10-Q are forward-looking
statements. Although the Working Interest Owners (as defined herein) have advised the Trust that they believe that the expectations reflected in the forward-looking statements contained herein are
reasonable, no assurance can be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations ("Cautionary
Statements") are disclosed in this Form 10-Q, including, without limitation, in conjunction with the forward-looking statements included in this Form 10-Q. A
summary of certain principal risks and Cautionary Statements is also included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2006 under
Part I, Item 1A. "Risk Factors." All subsequent written and oral forward-looking statements attributable to the Trust or persons acting on its behalf are expressly qualified in their entirety
by the Cautionary Statements.

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PART IFINANCIAL INFORMATION

Item 1. Financial Statements.

TEL OFFSHORE TRUST  STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS    (Unaudited)

|                                                                                                                                        |  | September 30,
2007 |           | December 31,
2006
|--------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------ | --------- | -----------------
|Assets                                                                                                                                  |  |                    |           |                  
|Cash and cash equivalents                                                                                                               |  | $                  | 4,753,103 |                  
|Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,224,656 and $28,214,149, respectively |  |                    | 42,999    |                  
|                                                                                                                                        |  |                    |           |                  
|Total assets                                                                                                                            |  | $                  | 4,796,102 |                  
|                                                                                                                                        |  |                    |           |                  
|Liabilities and Trust Corpus                                                                                                            |  |                    |           |                  
|Distribution payable to Unit holders                                                                                                    |  | $                  | 2,836,896 |                  
|Reserve for future Trust expenses                                                                                                       |  |                    | 1,916,207 |                  
|Commitments and contingencies                                                                                                           |  |                    |           |                  
|Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)                                                        |  |                    | 42,999    |                  
|                                                                                                                                        |  |                    |           |                  
|Total liabilities and Trust corpus                                                                                                      |  | $                  | 4,796,102 |                  
|                                                                                                                                        |  |                    |           |                  

STATEMENTS OF DISTRIBUTABLE INCOME    (Unaudited)

|                                                         |  | Three Months Ended
September 30, |           | Nine Months Ended
September 30, |  
|-------------------------------------------------------- |  | -------------------------------- | --------- | ------------------------------- | -
|
|Royalty income                                           |  | $                                | 2,924,013 |                                 | $
|Interest income                                          |  |                                  | 22,596    |                                 |  
|                                                         |  |                                  |           |                                 |  
|                                                         |  |                                  | 2,946,609 |                                 |  
|Decrease/(Increase) in reserve for future Trust expenses |  |                                  | 58,959    |                                 |  
|General and administrative expenses                      |  |                                  | (168,672  | )                               |  
|                                                         |  |                                  |           |                                 |  
|Distributable income                                     |  | $                                | 2,836,896 |                                 | $
|                                                         |  |                                  |           |                                 |  
|Distributions per Unit (4,751,510 Units)                 |  | $                                | 0.597051  |                                 | $
|                                                         |  |                                  |           |                                 |  

The
accompanying notes are an integral part of these financial statements.

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STATEMENTS OF CHANGES IN TRUST CORPUS    (Unaudited)

|                                                |  | Three Months Ended
September 30, |           | Nine Months Ended
September 30, |  
|----------------------------------------------- |  | -------------------------------- | --------- | ------------------------------- | -
|
|Trust corpus, beginning of period               |  | $                                | 46,301    |                                 | $
|Distributable income                            |  |                                  | 2,836,896 |                                 |  
|Distribution payable to Unit holders            |  |                                  | 2,836,896 |                                 |  
|Amortization of net overriding royalty interest |  |                                  | (3,302    | )                               |  
|                                                |  |                                  |           |                                 |  
|Trust corpus, end of period                     |  | $                                | 42,999    |                                 | $
|                                                |  |                                  |           |                                 |  

The
accompanying notes are an integral part of these financial statements.

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TEL OFFSHORE TRUST  NOTES TO FINANCIAL STATEMENTS  (Unaudited)

Note 1Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of
Dissolution ("Plan") approved by Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the
Trust owns a 99.99% interest and Tenneco Oil Company ("Tenneco") initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest ("Royalty")
equivalent to a 25% net profits interest in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. ("Exploration I") located offshore Louisiana to the Partnership
and issuing certificates evidencing units of beneficial interest in the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock.

On
October 31, 1986, Exploration I was dissolved and the oil and gas properties of Exploration I were distributed to Tenneco subject to the Royalty. Tenneco, who was then serving
as the Managing General Partner of the Partnership, assumed the obligations of Exploration I, including its obligations under the instrument conveying the Royalty to the Partnership (the
"Conveyance"). The dissolution of Exploration I had no impact on future cash distributions to holders of units of beneficial interest.

On
November 18, 1988, Chevron U.S.A., Inc. ("Chevron") acquired most of the Gulf of Mexico offshore oil and gas properties of Tenneco, including all of the Royalty
Properties. As a result of the acquisition, Chevron replaced Tenneco as the Working Interest Owner and Managing General Partner of the Partnership. Chevron also assumed Tenneco's obligations under the
Conveyance.

On
October 30, 1992, PennzEnergy Company ("PennzEnergy") (which merged with and into Devon Energy Production Company L.P. effective January 1, 2000) acquired certain oil
and gas producing properties from Chevron, including four of the Royalty Properties. The four Royalty Properties acquired by PennzEnergy were East Cameron 354, Eugene Island 348, Eugene Island 367 and
Eugene
Island 208. As a result of such acquisition, PennzEnergy replaced Chevron as the Working Interest Owner of such properties on October 30, 1992. PennzEnergy also assumed Chevron's obligations
under the Conveyance with respect to these properties.

On
December 1, 1994, Texaco Exploration and Production Inc. ("TEPI") acquired two of the Royalty Properties from Chevron. The Royalty Properties acquired by Texaco were
West Cameron 643 and East Cameron 371. As a result of such acquisitions, TEPI replaced Chevron as the Working Interest Owner of such properties on December 1, 1994. TEPI also assumed Chevron's
obligations under the Conveyance with respect to these properties.

On
October 1, 1995, SONAT Exploration Company ("SONAT") acquired the East Cameron 354 property from PennzEnergy. In addition, on October 1, 1995, Amoco Production Company
("Amoco") acquired the Eugene Island 367 property from PennzEnergy. As a result of such acquisitions, SONAT and Amoco replaced PennzEnergy as the Working Interest Owners of the East Cameron 354 and
Eugene Island 367 properties, respectively, on October 1, 1995 and also assumed PennzEnergy's obligations under the Conveyance with respect to these properties.

Effective
January 1, 1998, Energy Resource Technology, Inc. ("ERT") acquired the East Cameron 354 property from SONAT. As a result of such acquisition, ERT replaced SONAT
as the Working

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Interest
Owner of the East Cameron 354 property effective January 1, 1998, and also assumed SONAT's obligations under the Conveyance with respect to such property. In October 1998,
Amerada Hess Corporation ("Amerada") acquired the East Cameron 354 property from ERT effective January 1, 1998. As a result of such acquisition, Amerada replaced ERT as the Working Interest
Owner of the East Cameron 354 property effective January 1, 1998, and also assumed ERT's obligations under the Conveyance with respect to this property.

Effective
January 1, 2000 PennzEnergy and Devon Energy Corporation (Nevada) merged into Devon Energy Production Company L.P. ("Devon"). As a result of such merger, Devon replaced
PennzEnergy as the Working Interest Owner of Eugene Island 348 and Eugene Island 208 properties effective January 1, 2000, and also assumed PennzEnergy's obligations under the Conveyance with
respect to these properties. The abandonment obligations for Eugene Island 348 have been assumed by Maritech Resources, Inc. effective January 1, 2005.

On
October 9, 2001, a wholly owned subsidiary of Chevron Corporation, a Delaware corporation, merged (the "Merger") with and into Texaco Inc., a Delaware corporation
("Texaco"), pursuant to an Agreement and Plan of Merger, dated as of October 15, 2000. As a result of the Merger, Texaco Inc. became a wholly owned subsidiary of Chevron Corporation, and
Chevron Corporation changed its name to "ChevronTexaco Corporation" in connection with the Merger. Effective May 9, 2005, ChevronTexaco Corporation changed its name to Chevron Corporation.
Accordingly, the properties referred to herein by Chevron and Texaco are each now controlled by subsidiaries of Chevron Corporation.

On
May 1, 2002, TEPI assigned all of its interests in West Cameron 643 and East Cameron 371 to Chevron. Accordingly, pursuant to the Conveyance of the Royalty Properties, Net
Proceeds will be calculated for the collective Royalty Properties owned by Chevron after this date.

On
June 6, 2003, Anadarko Petroleum Corporation ("Anadarko") acquired, among other interests, a 25% Working Interest in the East Cameron 354 field subject to the Royalty from
Amerada effective April 1, 2003. As a result of this transaction, Anadarko replaced Amerada as the Working Interest Owner of East Cameron 354 effective July 1, 2003 and also assumed
Amerada's obligations under the Conveyance with respect to this property.

Effective
October 1, 2004, Apache acquired Anadarko's interest in East Cameron 354 and assumed Anadarko's obligations under the conveyance with respect to this property.

All
of the Royalty Properties continue to be subject to the Royalty, and it is anticipated that the Trust and the Partnership, in general, will continue to operate as if the
above-described sales of the Royalty Properties had not occurred.

Unless
the context in which such terms are used indicates otherwise, in these Notes to Financial Statements the terms "Working Interest Owner" and "Working Interest Owners" generally
refer to the owner or owners of the Royalty Properties (Exploration I through October 31, 1986; Tenneco for periods from October 31, 1986 until November 18, 1988; Chevron
with respect to all Royalty Properties for periods from November 18, 1988 until October 30, 1992, and with respect to all Royalty Properties except East Cameron 354, Eugene Island 348,
Eugene Island 367 and Eugene Island 208 for periods from October 30, 1992 until December 1, 1994, and with respect to the same properties except West Cameron 643 thereafter;
PennzEnergy/Devon with respect to East Cameron 354, Eugene Island 348, Eugene Island 367 and Eugene/Devon Island 208 for periods from October 30, 1992 until October 1,

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1995,
and with respect to Eugene Island 348 and Eugene Island 208 thereafter; TEPI with respect to West Cameron 643 and East Cameron 371 for periods beginning on or after December 1, 1994 until
May 1, 2002; SONAT with respect to East Cameron 354 for periods beginning on or after October 1, 1995; Amoco with respect to Eugene Island 367 for periods beginning on or after
October 1, 1995; Amerada with respect to East Cameron 354 for periods beginning on or after January 1, 1998 until July 1, 2003; Chevron with respect to West Cameron 643 and East
Cameron 371 on and after May 1, 2002; Anadarko with respect to East Cameron 354 on and after July 1, 2003 until October 1, 2004; and Apache with respect to East Cameron 354 after
October 1, 2004).

The
Trust is currently administered by The Bank of New York Trust Company, N.A., which succeeded JPMorgan Chase Bank, N.A. as the Corporate Trustee, effective October 2, 2006
pursuant to an agreement under which The Bank of New York acquired substantially all of the Corporate Trust business of JPMorgan Chase (formerly known as The Chase Manhattan Bank), and Daniel O.
Conwill, IV, Gary C. Evans and Jeffrey S. Swanson ("Individual Trustees"), as trustees ("Trustees").

Note 2Basis of Accounting

The accompanying unaudited financial information has been prepared by The Bank of New York Trust Company, N.A. ("Corporate Trustee") in accordance with the
instructions to Form 10-Q. The accompanying financial information is prepared on a comprehensive basis of accounting other than accounting principles generally accepted in the
United States of America. The Corporate Trustee and the individual trustees (collectively, the "Trustees") believe that the disclosures are adequate to make the information presented not misleading.
The information furnished reflects all adjustments which are, in the opinion of the Trustees, necessary for a fair presentation of the results for the interim periods presented. The financial
information should be read in conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31,
2006.

The
financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, which is
calculated on a

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units-of-production
basis, is charged directly to Trust corpus since such amount does not affect distributable income.

Cash
and cash equivalents include all highly liquid, short-term investments with original maturities of three months or less.

The
changes in reserve for future Trust expenses includes both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve
during periods when the Trust has insufficient income to pay Trust expenses.

The
Trust reviews the net overriding royalty interest in oil and gas properties for possible impairment whenever events or circumstances indicate the carrying amount of the asset may not
be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the use of the asset
and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss may be recognized to write down the asset to the lower of its estimated fair value
or net book value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's best estimate of assumptions concerning expected future
conditions. There were no write downs taken in the periods presented.

The
Special Cost Escrow account (Note 5) is established for the future costs to be incurred to plug and abandon wells, dismantle and remove platforms, pipelines and other
production facilities and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special Cost Escrow account are not reflected in the financial
statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in Royalty income.

The
preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect amounts reported in the financial statements as well as certain
discounts. Actual results could differ from those estimates.

The
amount of cash distributions by the Trust is dependent on, among other things, the sales prices for oil and gas produced from the Royalty Properties and the quantities of oil and gas
sold. It should be noted that substantial uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and
other actions taken by major petroleum producing nations, as well as the regional supply and demand for gas, weather, industrial growth, conservation measures, competition and other variables. The
Trust does not enter into any hedging transactions on future production.

Note 3Net Overriding Royalty Interest

The Royalty entitles the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1,
1983, provides that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net
Proceeds from their oil and gas properties for the period. Generally, "Net Proceeds" means the amounts received by the Working Interest Owners from the sale of minerals from the Royalty Properties
less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and a Special
Cost Escrow account. The Special Cost Escrow account (See Note 5) is established for the future costs to be incurred to plug and abandon wells,

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dismantle
and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include amounts
received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through
the future delivery of gas.

Note 4Distributions to Unit Holders

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and
any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. Such distributions are referred to as "distributable
income." The amounts distributed are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each calendar quarter. However, cash distributions are
made in January, April, July and October and include interest earned from the quarterly record date to the date of distribution.

During
2005, Hurricane Katrina and Hurricane Rita caused significant damage to various platforms and third-party transportation systems which resulted in oil and gas production delays in
the Royalty Properties. During 2006 several of the platforms and facilities on the Royalty Properties were restored; however, certain projects remain to be completed during 2007 to increase production
to pre-hurricane levels. The Trust may have to fund its share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties.
Further delays in repairs on third-party transportation systems may continue to limit production.
Additionally, the extensive damage caused by these hurricanes has led to significant demand for services and supplies for repairs in the offshore Gulf of Mexico, which has increased current and future
levels of expenditures. The reduced oil and gas production and increased costs reduced the cash income distributions to unitholders significantly during 2006 and may continue to affect cash income
distributions during a portion or all of 2007. During the fourth quarter 2006, the Trust resumed distributions. The fourth quarter distribution of $1.7 million was paid on January 11,
2007. On June 27, 2007, the Trust announced its second quarter distribution of approximately $2.0 million, which was paid on July 9, 2007. On September 27, 2007, the Trust
announced its third quarter distribution of approximately $2.8 million.

Note 5Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for the
reserve of funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount
of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors,
including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net profits interest. Deposits into this account reduce
current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost Escrow" account. The
Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs. Special Cost Escrow funds will generally be utilized to pay
Special Costs to the extent there are not adequate current net profits interest to pay such costs. Special Costs that have been paid are no longer included in the Special Cost

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Escrow
calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of estimated future Special Costs and there
is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the Conveyance). When there is not a Net
Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost Escrow account will also be
released when the balance in such account exceeds 125% of estimated future Special Costs. In the third quarter of 2007, there was a net release of funds from the Special Cost Escrow account of
approximately $455,000. As of September 30, 2007, $6,886,874 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the financial
statements of the Trust.

Chevron,
in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account may be required in future
periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a
significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Note 6Reserve For Future Trust Expenses

The Trust made a determination in 1998 to maintain a cash reserve equal to approximately three times the average expenses of the Trust during each of the past
three years to provide for future administrative expenses in connection with the winding up of the Trust. During the first nine months of 2007, the Trust increased its reserve by $292,341 for a
reserve balance of $1,916,207 as of September 30, 2007. The reserve amount at September 30, 2006 was $877,804.

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Item 2.        Management's Discussion and Analysis of Financial Condition and Results of Operations.

Critical Accounting Policies

The financial statements of the Trust are prepared on the following basis:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles, because, under such principles,
Royalty income and Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a
units-of-production basis, is charged directly to Trust corpus since such amount does not affect distributable income.

The
Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of the Working
Interest Owners.

Financial Review

Three Months Ended September 30, 2007 and 2006

There were distributions of $2,836,896 or $0.597051 per Unit to the Unit holders for the three months ended September 30, 2007 as compared to no
distributions for the same period in 2006. There was no distributable income for the third quarter of 2006 primarily as a result of damages caused to the Royalty Properties by Hurricanes Rita and
Katrina discussed below in "Operational Review" and a required deposit to the Special Cost Escrow account.

Crude
oil and condensate revenues increased $2,451,269, or 36%, to $9,310,472 in the third quarter of 2007 as compared to $6,859,202 in the third quarter of 2006. The increase was a
result of a 34% increase in crude oil and condensate volume to 137,016 barrels in the third quarter of 2007 from 102,070 barrels in the third quarter of 2006 due to higher production volume, and a 1%
increase in the average price of crude oil and condensate to $67.95 per barrel in the third quarter of 2007 from $67.20 per barrel in the third quarter of 2006.

Gas
revenues increased $1,690,733, or 241%, to $2,392,092 in the third quarter of 2007 from $701,359 in the third quarter of 2006, due primarily to an increase in gas volumes of 187% to
307,288 Mcf in the third quarter of 2007 from 107,013 Mcf in the third quarter of 2006. The average price

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received
for natural gas was $7.78 per Mcf in the third quarter of 2007, compared to $6.55 per Mcf in the third quarter of 2006. Gas products revenue increased to $221,384 in the third quarter of 2007
from $4,297 in the third quarter of 2006, primarily due to an increase in production volumes to 208,868 gallons in the third quarter of 2007 from 4,092 gallons in the third quarter of 2006.

The
Trust's share of capital expenditures decreased $1,356,748, from $1,569,916 in the third quarter of 2006 to $213,168 in the third quarter of 2007. The higher amount of capital
expenditures for the third quarter of 2006 related primarily to damages caused by Hurricanes Rita and Katrina.

The
Royalty Properties had an undistributed net loss of $24,114 for the third quarter of 2007.

In
the third quarter of 2007, there was a net release of funds into the Special Cost Escrow account. The Trust's share of the net funds released was $454,995. As of September 30,
2007, $6,886,874 remained in the Special Cost Escrow account. The Special Cost Escrow is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance.
For additional information relating to the Special Cost Escrow, see "Special Cost Escrow Account" below.

In
the third quarter of 2006, there was a net deposit of funds into the Special Cost Escrow account. The Trust's share of the net funds deposited was $592,718.

Nine Months Ended September 30, 2007 and 2006

There were distributions of $6,058,403 or $1.275048 per Unit to the Unit holders for the nine months ended September 30, 2007 as compared to no
distributions for the same period in 2006. There was no distributable income for the first nine months of 2006 primarily as a result of damages caused to the Royalty Properties by Hurricanes Rita and
Katrina discussed below in "Operational Review" and a required deposit to the Special Cost Escrow account.

Crude
oil and condensate revenues increased $8,976,296, or 50%, to $26,873,646 in the first nine months of 2007 as compared to $17,897,350 for the same period in 2006, due to a 49%
increase in crude oil and condensate volume to 433,006 barrels in the first nine months of 2007 from 290,987 barrels in the first nine months of 2006 and an increase in the average price of crude oil
and condensate to $62.06 per barrel from $61.51 per barrel, respectively, during these periods.

Gas
revenues increased $5,911,438, or 460%, to $7,196,098 in the first nine months of 2007 from $1,284,660 for the same period in 2006, due to an increase in gas volumes of 400% to
968,347 Mcf in the first nine months of 2007 from 193,820 Mcf for the same period in 2006 and a 12% increase in the average price received for natural gas to $7.43 per Mcf in the first nine months of
2007 from $6.63 per Mcf in the same period of 2006. Gas products revenue increased $401,495 or 345%, to $517,901 in the first nine months of 2007 from $116,406 in the same period of 2006, primarily
due to an increase in production volume of 402,196 gallons, or 271%, to 550,550 gallons in the first nine months of 2007 from 148,354 gallons in the same period of 2006.

The
increase in crude oil and condensate volume, as well as natural gas volumes and gas products production volume, for the first nine months of 2007, compared to the first nine months
of 2006, resulted primarily from repairs of certain damages caused by Hurricanes Rita and Katrina.

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The
Trust's share of capital expenditures decreased $7,564,000, from $8,951,892 in the first nine months of 2006 to $1,387,892 in the same period of 2007. The higher amount of capital
expenditures for the first nine months of 2006 related primarily to damages caused by Hurricanes Rita and Katrina.

The
Royalty Properties had an undistributed net loss of $24,114 for the first nine months of 2007.

In
the first nine months of 2007, there was a net deposit of funds into the Special Cost Escrow account. The Trust's share of the net funds deposited was $47,918. In the first nine
months of 2006, there was a net deposit of funds into the Special Cost Escrow account. The Trust's share of the net funds deposited was $1,472,956. As of September 30, 2007, $6,886,874 remained
in the Special Cost Escrow account. The Special Cost Escrow is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information
relating to the Special Cost Escrow, see "Special Cost Escrow Account" below.

Reserve for Future Trust Expenses

In accordance with the provisions of the Trust Agreement, generally all Royalty income received by the Trust, net of Trust general and administrative expenses and
any cash reserves established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. In the first quarter of 1998, the Trust determined that
the Trust's cash reserve was sufficient at that time to provide for future administrative expenses in connection with the winding up of the Trust. The Trust determined that a cash reserve equal to
approximately three times the average expenses of the Trust during each of the past three years was sufficient at this time to provide for future administrative expenses in connection with the winding
up of the Trust. During the third quarter of 2007, the Trust decreased its reserve by $58,958 for a reserve balance of $1,916,207 as of September 30, 2007. The reserve amount at
September 30, 2006 was $877,804.

Other

The amount of cash distributed by the Trust is dependent on, among other things, the sales prices and quantities of oil and gas produced from the Royalty
Properties as well as capital expenditures by the Working Interest Owners that may or may not be included in the Special Cost Escrow account. It should be noted that substantial uncertainties exist
with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions taken by major petroleum producing nations, as
well as the regional supply and demand for oil and gas, weather, industrial growth, conservation measures, competition and other variables.

Operational Review

At the end of October 2005, approximately half of Chevron oil-equivalent production in the Gulf of Mexico remained shut in due to damages from
hurricanes in the third quarter. The time it will take to resume this production is uncertain, and some of the volumes may not be sufficiently economic to restore. As of July 13, 2007, Eugene
Island 339 gas sales line was repaired and gas sales were resumed. The Working Interest Owner has also advised the Trust that the Working Interest Owner has completed the project to compress and
re-inject gas to the B-5 well, which allows the operator to increase oil production and to limit flaring of gas. Eugene Island 339 oil production increased during the third
quarter of 2006 and increased further during the fourth quarter of 2006 and the first quarter 2007 as the B-5 well gas injection project was completed. On Ship Shoal 182/183, gas
production and sales

11

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resumed
in July 2006 and full production resumed in the fourth quarter of 2006. On West Cameron 643, production was shut in from September 2005 following Hurricane Rita's major damage to
various platforms, but limited gas production resumed in late July 2006 before the wells loaded up and additional repairs were required thus requiring the well to be shut in again during the
second quarter 2006. Production at West Cameron 643 resumed May 2007.

Three Months Ended September 30, 2007 and 2006

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing General Partner of the
Partnership and by the applicable Working Interest Owners. The Trustees have no control over these operations or internal controls relating to this information.

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Ship
Shoal 182/183 crude oil revenues increased from $4,175,138 in the third quarter of 2006 to $4,744,516 in the third quarter of 2007, due to an increase in the average crude oil price
from $67.93 per barrel in the third quarter of 2006 to $69.12 per barrel for the same period in 2007. Crude oil production increased from 61,465 barrels in the third quarter of 2006 to 68,640 barrels
in the third
quarter of 2007. Gas revenues increased from $663,176 in the third quarter of 2006 to $1,968,734 in the third quarter of 2007, primarily due to an increase in gas production. Gas volumes increased
from 101,558 Mcf in the third quarter of 2006 to 249,347 Mcf in the third quarter of 2007. The natural gas sales price also increased from $6.53 per Mcf in the third quarter of 2006 to $7.90 per Mcf
in the third quarter of 2007. Capital expenditures decreased from $605,845 in the third quarter of 2006 to $97,197 in the third quarter of 2007. Operating expenses increased from $692,241 in the third
quarter of 2006 to $695,209 for the same period in 2007.

Eugene
Island 339 crude oil revenues increased from $2,555,170 in the third quarter of 2006 to $4,398,230 in the third quarter of 2007. There was an increase in crude oil production from
38,706 barrels in the third quarter of 2006 to 65,891 barrels in the third quarter of 2007. This was also an increase in the average price of crude oil from $66.02 per barrel in the third quarter of
2006 to $66.75 in the third quarter of 2007. Gas revenues were $0 in the third quarter of 2006 and $111,087 in the third quarter 2007 due to the repair of damages caused by Hurricanes Rita and Katrina
that caused gas production to increase from 0 Mcf in the third quarter of 2006 to 16,360 in the third quarter 2007. Capital expenditures decreased from $945,904 in the third quarter of 2006 to $52,909
in the third quarter of 2007, primarily due to decreased expenditures on the new oil sales pipeline and sales point as well as a gas injection compressor project. Operating expenses decreased from
$1,266,577 in the third quarter of 2006 to $653,172 for the same period in 2007, mostly due to workover expenses on well #B-12 that occurred in 2006.

West
Cameron 643 gas revenues increased from $0 in the third quarter of 2006 to $264,332 in the third quarter 2007 due to the repair of damage caused by Hurricanes Rita and Katrina that
caused gas production to increase from 0 Mcf in the third quarter of 2006 to 35,389 Mcf in the third quarter of 2007. Although limited gas production resumed in late July 2006, those revenues
were not included in third-quarter 2006 results of operations. Operating expenses increased from $97,716 in the third quarter of 2006 to $262,763 for the same period in 2007 due to increased
production. Capital expenditures were $0 in the third quarter of 2006 and 2007.

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East
Cameron 371 crude oil revenues were $0 in the third quarter of 2006 and 2007 due to the field being shut in. Gas revenues increased from $0 in the third quarter of 2006 to $9,046 in
the third quarter 2007 due to the repair of damage caused by Hurricanes Rita and Katrina that caused gas production to increase from 0 Mcf in the third quarter of 2006 to 1,199 Mcf in the third
quarter of 2007. Operating expenses increased from $17,235 in the third quarter of 2006 to $33,562 in the third quarter of 2007 due to increased production. There were no capital expenditures in the
third quarter of 2006 or 2007.

Nine Months Ended September 30, 2007 and 2006

Volumes and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Ship Shoal 182/183 crude oil revenues increased from $12,404,718 in the first nine months of 2006 to $13,421,822 in the first nine months of 2007, due to an
increase in crude oil production from 197,212 barrels in the first nine months of 2006 to 208,562 barrels in the first nine months of 2007. The increase was also due to an increase in the average
crude oil price from $62.90 per barrel in the first nine months of 2006 to $64.35 per barrel for the same period in 2007. Gas revenues increased from $663,176 in the first nine months of 2006 to
$6,453,632 in first nine months of 2007 primarily due to an increase in gas volumes from 101,558 Mcf in the first nine months of 2006 to 854,183 Mcf for the same period in 2007. This increase in gas
volumes resulted from no gas being produced until the third quarter of 2006 as a result of hurricane-related damages. The average natural gas sales price increased from $6.53 per Mcf in the first nine
months of 2006 to $7.56 in the first nine months of 2007. Capital expenditures decreased from $5,374,876 in the first nine months of 2006 to $675,220 in the same period of 2007, primarily due to a
decrease in hurricane-related repairs that occurred during 2006. Operating expenses increased from $1,703,593 for the first nine months of 2006 to $2,547,168 for the first nine months of 2007, due to
the costs related to increased production.

Eugene
Island 339 crude oil revenues increased from $5,145,024 in the first nine months of 2006 to $13,004,475 in the first nine months of 2007, primarily due to an increase in volumes
from 88,134 barrels in the first nine months of 2006 to 217,197 barrels in the first nine months of 2007. The price of crude oil increased from $58.38 per barrel in the first nine months of 2006 to
$59.87 per barrel in the first nine months of 2007. Gas revenues decreased from $547,819 in the first nine months of 2006 to $111,087 in the first nine months of 2007, primarily due to a decrease in
production from 83,101 Mcf for the first nine months of 2006 to 16,360 Mcf for the same period in 2007. Capital expenditures decreased from $3,510,917 in the first nine months of 2006 to $182,651 in
the first nine months of 2007 due to a decrease in the repair of hurricane-related damages. Operating expenses decreased from $1,842,775 for the first nine months of 2006 to $1,540,940 for the first
nine months of 2007, primarily due to lower workover expenses.

West
Cameron 643 gas revenues increased from $0 in the first nine months of 2006 to $483,549 in the first nine months of 2007 due to an increase in gas volumes from 0 Mcf in the first
nine months of 2006 to 77,482 Mcf for the same period in 2007. Operating expenses increased from $315,623 in the first nine months of 2006 to $788,183 for the first nine months of 2007 due to
increased production. Capital expenditures decreased from $46,156 in the first nine months of 2006 to $0 in the first nine months of 2007.

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East
Cameron 371 crude oil revenues were $0 in the first nine months of 2006 and 2007. Gas revenues increased from $0 in the first nine months of 2006 to $23,770 for the same period in
2007. Operating expenses increased from $25,436 in the first nine months of 2006 to $60,393 in the first nine months of 2007. There were no capital expenditures in the first nine months of 2007 or
2006.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to the Trust by DeGolyer and MacNaughton, independent petroleum engineers, as of October 31, 2006 future net revenues
attributable to the Trust's royalty interests were estimated at $38.3 million. Estimates of proved oil and gas reserves attributable to the Partnership's royalty interest are based on existing
economic and operating conditions in effect at October 31, 2006 in order to correspond with distributions to the Trust. Such reserve study also indicates that approximately 72% of the future
net revenues from the Royalty Properties are expected to be received by the Trust during the next three years. In addition, because the Trust will terminate in the event estimated future net revenues
fall below $2.0 million, it would be possible for the Trust to terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the
Trust, the Trustees will sell for cash all of the assets held in the Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied.
The estimates of future net revenues discussed above are subject to large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating
future net revenues for the Royalty Properties. The estimate may vary depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed
by DeGolyer and MacNaughton. In addition, future economic and operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth
above is qualified in its entirety by reference to the Trust's Annual Report on Form 10-K for the year ended December 31, 2006. The Trust's Form 10-K is
available at the website of the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from the Corporate Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of
abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount
of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net
proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to
as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production costs.

Special
Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid
are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125%
of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the
Conveyance).

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When
there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the Special Cost
Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the first nine months of 2007, there was a net deposit of funds to the Special
Cost Escrow account of $47,918. In the first nine months of 2006, there was a net deposit of funds to the Special Cost Escrow account of $1,472,956.

As
of September 30, 2007, $6,886,874 remained in the Special Cost Escrow account.

Chevron,
in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account may be required in future
periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a
significant reduction in Royalty income in the periods in which such deposits are made, including the possibility that no Royalty income would be received in such periods.

Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas recorded by the Working Interest
Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and the royalties paid to the Trust during the periods indicated. Net Proceeds due to the
Trust are calculated for each three month period commencing on the first day of February, May, August and November.

|                                                            |  | Royalty Properties Three Months
Ended September 30,(1) |           
|----------------------------------------------------------- |  | ------------------------------------------------------ | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                        | 137,016   
|Natural gas and gas products (Mcfe)                         |  |                                                        | 337,127   
|Crude oil and condensate average price, per bbl             |  | $                                                      | 67.95     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                      | 7.78      
|Crude oil and condensate revenues                           |  | $                                                      | 9,310,472 
|Natural gas and gas products revenues                       |  |                                                        | 2,613,476 
|Production expenses                                         |  |                                                        | (2,070,514
|Capital expenditures                                        |  |                                                        | (213,168  
|Undistributed Net Loss (Income)(2)                          |  |                                                        | 24,114    
|Refund Of/(Provision for) Special Cost Escrow               |  |                                                        | 2,032,842 
|                                                            |  |                                                        |           
|Net Proceeds                                                |  |                                                        | 11,697,222
|Royalty interest                                            |  |                                                        | x25       
|                                                            |  |                                                        |           
|Partnership share                                           |  |                                                        | 2,924,305 
|Trust interest                                              |  |                                                        | x99.99    
|                                                            |  |                                                        |           
|Trust share of Royalty Income                               |  | $                                                      | 2,924,013 
|                                                            |  |                                                        |           

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15

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|                                                            |  | Royalty Properties Nine Months
Ended September 30,(1) |           
|----------------------------------------------------------- |  | ----------------------------------------------------- | ----------
|
|Crude oil and condensate (bbls)                             |  |                                                       | 433,006   
|Natural gas and gas products (Mcfe)                         |  |                                                       | 1,046,997 
|Crude oil and condensate average price, per bbl             |  | $                                                     | 62.06     
|Natural gas average price, per Mcf (excluding gas products) |  | $                                                     | 7.43      
|Crude oil and condensate revenues                           |  | $                                                     | 26,873,646
|Natural gas and gas products revenues                       |  |                                                       | 7,713,999 
|Production expenses                                         |  |                                                       | (6,242,463
|Capital expenditures                                        |  |                                                       | (1,387,892
|Undistributed Net Loss (Income)(2)                          |  |                                                       | 24,114    
|Refund of/ (Provision for) Special Cost Escrow              |  |                                                       | 448,302   
|                                                            |  |                                                       |           
|Net Proceeds                                                |  |                                                       | 27,429,706
|Royalty interest                                            |  |                                                       | x25       
|Partnership share                                           |  |                                                       | 6,857,426 
|Trust interest                                              |  |                                                       | x99.99    
|                                                            |  |                                                       |           
|Trust share of Royalty Income                               |  | $                                                     | 6,856,741 
|                                                            |  |                                                       |           

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Item 3.        Quantitative and Qualitative Disclosures About Market Risk.

No material changes have occurred since our Annual Report on Form 10-K for the year ended December 31, 2006. Reference is also made to
Note 2 of the Notes to Financial Statements included in Part I, Item 1 of this Form 10-Q.

Item 4.        Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls
and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the "Exchange
Act"), is recorded, processed, summarized and reported within the time periods specified in

16

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the
SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Trust in
the reports that it files or submits under the Exchange Act is accumulated and communicated by Chevron, as the managing general partner of the Partnership, and the Working Interest Owners to The Bank
of New York Trust Company, N.A., as Corporate Trustee of the Trust, and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions
regarding required disclosure.

As
of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Mike Ulrich, as Vice President of
the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust were effective at that time.

Due
to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding
information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners, including historical operating data, plans for future
operating and capital expenditures, reserve information and information relating to projected production, (B) information from the managing general partner of the Partnership, including
information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent reserve engineers. See Part I, Item 1A.
"Risk FactorsThe Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little influence over operation or development" and
"The Trustees rely upon the working interest owners and managing general partner for information regarding the Royalty Properties" in the Trust's Annual Report on
Form 10-K for the year ended December 31, 2006, and "Note 5Negative Adjustments" of the financial statements and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" relating to operating information on East Cameron 371 included in the Annual Report on Form 10-K for the year ended
December 31, 2006 for a description of certain risks relating to these arrangements and reliance and applicable adjustments to operating information when reported by the Working Interest Owners
to the Corporate Trustee and recorded in the Trust's results of operations.

Changes in Internal Control Over Financial Reporting.During the three months ended September 30, 2007, there has been
no change in the Corporate Trustee's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Corporate Trustee's internal control over
financial reporting relating to the Trust. The Corporate Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over
financial reporting of the Working Interest Owners or the managing general partner of the Partnership.

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PART IIOTHER INFORMATION

Item 1A.     Risk Factors.

There have not been any material changes from risk factors previously disclosed in the Trust's response to Item 1A to Part I of the Trust's Annual Report
on Form 10-K for the year ended December 31, 2006.

Item 6.        Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)

|       |  |   |  |                                                                                                                                                                                                                                                                                                                              |  | SEC File or Registration Number |  | Exhibit Number
|------ |  | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------- |  | --------------
|4(a)*  |  |  |  | Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust) |  | 0-06910                         |  | 4(a)          
|4(b)*  |  |  |  | Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended
December 31, 1992 of TEL Offshore Trust)                                                                                          |  | 0-06910                         |  | 4(b)          
|4(c)*  |  |  |  | Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                          |  | 0-06910                         |  | 4(c)          
|4(d)*  |  |  |  | Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)                                                                                                                                                                        |  | 0-06910                         |  | 4(d)          
|4(e)*  |  |  |  | Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the year ended December 31, 1992 of TEL Offshore
Trust)                                                                                                                  |  | 0-06910                         |  | 4(e)          
|10(a)* |  |  |  | Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)                                                                                                                      |  | 0-06910                         |  | 10(a)         
|10(b)* |  |  |  | Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)                                                                                                                                           |  | 0-06910                         |  | 10(b)         
|10(c)* |  |  |  | Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC-Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore
Trust)                                                                                                                    |  | 0-06910                         |  | 10(c)         
|10(d)* |  |  |  | Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31,
1993 of TEL Offshore Trust)                                                                                                |  | 0-06910                         |  | 10(d)         
|31     |  |  |  | Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                            |  |                                 |  |               
|32     |  |  |  | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                                                                            |  |                                 |  |               

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.

|                        |  | TEL OFFSHORE TRUST
|----------------------- |  | ------------------
|                        |  | By:               
|                        |  | By:               
|Date: November 14, 2007 |  |                   

The Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions.
Accordingly, no additional signatures are available and none have been provided.

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